The present invention relates to a method for controlling the pH of steam fluids. More particularly, the invention relates to a method for (1) preserving the reservoir rock and/or gravel packing in oil wells being subjected to steam enhanced oil recovery techniques; (2) preventing permeability damage to hydrocarbon-bearing formations which contain clay minerals; (3) controlling corrosion produced by an acidic vapor phase condensate of the steam; and (4) improving the steam injection rate into the formation.
Steam injection techniques such as steam stimulation and steamflooding, have been used to recover immobile heavy oils and to enhance the oil recovery from older wells where the natural field pressures are too low for unassisted production. They are designed to reduce the reservoir flow resistance by reducing the viscosity of the crude.
These techniques involve injection into the well of a high temperature wet steam in cycles of thousands of cubic meters at a time. Wet steam is a mixture of steam and varying amount of hot liquid water, the quality of wet steam generally ranging from 35% to 80%. Because of the density difference between the two phases of the wet steam, the vapor phase preferentially enters the upper part of the injection interval and the liquid phase preferentially enters the lower part.
When groundwater, river water, or lake water is used as feedwater to generate wet steam, the liquid water phase is generally basic (having a pH in excess of 11) and the vapor phase of the wet steam, when condensed, is acidic (having a pH of about 4.0 to 4.5). This partitioning is because of bicarbonate contained in the source water decomposing to CO.sub.2 and OH.sup.-, as shown in Equation 1 below: ##STR1## The CO.sub.2 is volatile and enters the vapor phase, which produces a low pH in the liquids condensed from the vapor phase. The OH.sup.- ion enters the liquid phase and causes a high pH in the liquid phase.
Associated with using these wet steams in steam injection is the problem of silica and silicate dissolution. Coupled with high fluid temperatures, both the liquid phase and the liquids from the condensed vapor phase are capable of rapidly dissolving reservoir rocks, such as sandstone, carbonate, diatomite, procellanite and the like. For pH values above 11.0 and temperatures above 177.degree. C., the silica and silicate dissolution rates are orders of magnitude higher than at neutral/ambient conditions. Also, because the reactions for dissolving siliceous reservoir rocks are base consumers in alkaline fluids, the pH of the residual fluid decreases rapidly as the fluid moves away from the wellbore, causing the dissolution reactions and solubility to diminish raidly and causing the reaction products downstream (such as alumino-silicates and other metal silicates) to precipitate in the pores. This precipitation decreases the formation permeability and decreases well injectivity.
Dissolution of the gravel pack has been shown to be primarily a function of the pH and temperature of the injected liquid-phase water. Prior attempts at solution of the problem have focused on these aspects. For example, by keeping the pH of the injected hot water below 10, gravel pack dissolution can be decreased sharply. This may be accomplished by treating the feed water with acid to yield the desired effluent pH.
Using acid to neutralize the bicarbonate alkalinity, was suggested by M. G. Reed in "Gravel Pack and Formation Sandstone Dissolution During Steam Injection", Journal of Petroleum Technology, Vol. 32, pp. 941-949 (1980). But this approach suffers from considerations of costs as well as feasibility of the method. That is, addition of too much acid will cause severe corrosion of the steam generator and too little will result in insufficient depression of the pH to alleviate silica loss.
U.S. Pat. No. 4,475,595 to Watkins et al, filed Aug. 23, 1982, which is hereby incorporated by reference, addresses the problem of silica dissolution during steam injection. Watkins et al discuss adding an ammonium salt to the generator feedwater or to the steam itself. The resulting ammonia gas generated from decomposition of the ammonium salt partitions to the vapor phase leaving an acidic component to neutralize the OH.sup.- ions in the residual liquid phase.
Another problem associated with Equation (1) is its effect on the vapor phase of the steam. The carbon dioxide partitions into the vapor phase while the hydroxyl ions remain in the liquid phase. The vapor phase of the wet steam, when condensed, may have an acidic pH of about 4.0 to 4.5 resulting from the carbon dioxide combining with water to form carbonic acid, a known corrosive. Carbonic acid causes corrosion of steel conduit with which it comes in contact and combines with alkaline earth ions to form scale which adheres to the surfaces of the pores in the reservoir, the well bore and other conduits and builds up in thickness over a period of time.
U.S. Pat. No. 4,476,930 to Watanabe, filed Aug. 23, 1982, which is hereby incorporated by reference, addresses the problem of scale inhibition during steam generation. Watanabe discusses adding an ammonium salt to the steam generator feedwater. Ammonia gas partitions to the vapor phase and inhibits the production of carbonic acid.
U.S. Ser. No. 164,924 to Nigrini et al, entitled "Method for Controlling the pH of Steam Fluids", field March 7, 1988, now U.S. Pat. No. 4,871,023 also addresses the problem of silica dissolution during steam injection. Nigrini et al discuss adding phosphorus, arsenic, antimony and bismuth-containing compounds to the steam which alter its pH.
Also associated with injecting wet steam is the problem of permeability damage of formations containing clay. Formations that contain clay minerals are susceptible to water-rock interactions that cause the clay to disperse and migrate. When they move downstream, they tend to bridge in pore constrictions to form miniature filter-cakes throughout the pore network. This can decrease steam injectivity in the lower interval where liquid water is injected and also in the upper interval where vapor phase condensation takes place. In some cases, clay structural expansion may contribute to this decrease in permeability.
U.S. Pat. No. 4,549,609 to Watkins et al, which is hereby incorporated by reference, addresses the problem of permeability damage of formations containing clay. Watkins et al injection a steam containing an ammonical nitrogen-containing compound. Ammonia is effective for clay stabilization.
U.S. Pat. No. 4,714,112, to Hsueh et al, entitled "Method for Inhibiting Silica Dissolution and Pipe Corrosion During Oil Well Steam Injection", filed June 22, 1987, discusses reducing silica dissolution and preventing permeability damage using ammonia-containing compounds.
While some well-treating methods have met with some success, the need exists for an improved method which inhibits silica dissolution and prevents permeability damage of formations containing clay minerals. Accordingly, it is the principal object of this invention to provide such methods.